UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

|X| Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2002

|_| Transition Report Pursuant to Section 13 or 15(d) or the Securities Exchange Act of 1934

For the transition period from to

Commission file number 1-12074

STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

                                           Delaware                                                                 72-1235413
                             (State or other jurisdiction                                                (I.R.S. Employer
                         of incorporation or organization)                                        Identification No.)

                              625 E. Kaliste Saloom Road                                                     70508
                                    Lafayette, Louisiana                                                         (Zip code)
                   (Address of principal executive offices)

Registrant's telephone number, including area code: (337) 237-0410

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
Yes |X| No |_|

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes |X| No |_|

As of November 4, 2002 there were 26,336,532 shares of the registrant's Common Stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of September 30, 2002 and December 31, 2001	1

	Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2002 and 2001	2

	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2002 and 2001	3

	Notes to Condensed Consolidated Financial Statements	4

	Report of Independent Public Accountants	8

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	9

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	14

Item 4.	Controls and Procedures	15

PART II. – OTHER INFORMATION

Item 1.	Legal Proceedings	15

Item 6.	Exhibits and Reports on Form 8-K	15

Signature		16

Certification of Principal Executive Officer		17

Certification of Principal Financial Officer		18

PART I - FINANCIAL INFORMATION
Item 1. Financial Statements

STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands)

	September 30, 2002		December 31, 2001
Assets	(Unaudited)
Current assets:
Cash and cash equivalents	$23,342		$13,155
Accounts receivable	57,273		46,987
Put contracts	2,010		26,207
Other current assets	8,118		1,832

Total current assets	90,743		88,181

Oil and gas properties:
Proved, net of accumulated depreciation, depletion and amortization of $1,136,185 and $1,015,455, respectively	920,459		880,534
Unevaluated	108,251		113,372
Building and land, net	5,260		5,352
Fixed assets, net	5,339		4,883
Put contracts	902		-
Other assets, net	13,812		9,461

Total assets	$1,144,766		$1,101,783

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$57,827		$69,197
Undistributed oil and gas proceeds	25,625		23,741
Deferred taxes	-		5,312
Fair value of swap contract	5,530		2,194
Other current liabilities	8,617		5,834

Total current liabilities	97,599		106,278

Long–term debt	436,000		426,000
Production payments	1,144		4,323
Deferred taxes	50,645		30,244
Fair value of swap contract	1,036		3,619
Other long–term liabilities	2,107		1,294

Total liabilities	588,531		571,758


Common stock	263		262
Additional paid–in capital	453,157		449,111
Retained earnings	111,057		75,213
Treasury stock	(1,706	)	(2,057	)
Other comprehensive income (loss)	(6,536	)	7,496

Total stockholders’ equity	556,235		530,025

Total liabilities and stockholders’ equity	$1,144,766		$1,101,783

The accompanying notes are an integral part of this balance sheet.

STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2002	2001		2002	2001
Revenues:
Oil and gas production	$94,523	$82,366		$275,491	$331,371
Other revenues	734	716		2,254	2,441

Total revenues	95,257	83,082		277,745	333,812

Expenses:
Normal lease operating expenses	15,563	12,543		45,936	35,491
Major maintenance expenses	5,112	1,765		11,074	4,371
Production taxes	1,496	1,736		3,596	5,255
Depreciation, depletion and amortization	39,662	47,537		122,577	126,061
Write–down of oil and gas properties	-	237,741		-	237,741
Interest	5,900	771		17,386	2,589
Salaries, general and administrative expenses	2,930	3,194		9,480	9,114
Incentive compensation plan	192	-		571	523
Non–cash derivative expenses	3,337	889		11,844	2,223
Merger expenses	-	88		-	25,719

Total expenses	74,192	306,264		222,464	449,087

Net income (loss) before income taxes	21,065	(223,182	)	55,281	(115,275	)

Provision (benefit) for income taxes:
Current	-	-		-	500
Deferred	7,372	(78,114	)	19,348	(39,034	)

Total income taxes	7,372	(78,114	)	19,348	(38,534	)

Net income (loss)	$13,693	($145,068	)	$35,933	($76,741	)

Earnings (loss) per common share:
Basic earnings (loss) per share	$0.52	($5.54	)	$1.37	($2.94	)

Diluted earnings (loss) per share	$0.52	($5.54	)	$1.36	($2.94	)

Average shares outstanding	26,337	26,184		26,317	26,084

Average shares outstanding assuming dilution	26,485	26,184		26,497	26,084

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)

	Nine Months Ended September 30,
	2002		2001
Cash flows from operating activities:
Net income (loss)	$35,933		($76,741	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization	122,577		126,061
Write-down of oil and gas properties	-		237,741
Provision (benefit) for deferred income taxes	19,348		(39,034	)
Non-cash effect of production payments	(2,979	)	(4,691	)
Non-cash derivative expenses	11,844		2,223
Other non-cash expenses	548		912

	187,271		246,471

Decrease in marketable securities	-		300
(Increase) decrease in accounts receivable	(10,286	)	42,416
Increase in other current assets	(2,305	)	(526	)
Increase (decrease) in other accrued liabilities	4,667		(10,152	)
Investment in put contracts	(9,384	)	(6,466	)
Other	-		(1,251	)

Net cash provided by operating activities	169,963		270,792

Cash flows from investing activities:
Investment in oil and gas properties	(167,435	)	(286,518	)
Building and fixed asset additions	(5,885	)	(721	)
Sale of unevaluated properties	419		1,366

Net cash used in investing activities	(172,901	)	(285,873	)

Cash flows from financing activities:
Proceeds from bank borrowings	22,000		5,000
Repayment of bank debt	(12,000	)	(53,000	)
Deferred financing costs	(283	)	-
Repurchase of treasury stock	-		(200	)
Proceeds from exercise of stock options	3,408		4,801

Net cash provided by (used in) financing activities	13,125		(43,399	)

Net increase (decrease) in cash and cash equivalents	10,187		(58,480	)

Cash and cash equivalents, beginning of period	13,155		78,557

Cash and cash equivalents, end of period	$23,342		$20,077

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$15,023		$4,715
Income taxes	-		500

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Interim Financial Statements

The condensed consolidated financial statements of Stone Energy Corporation and subsidiary as of September 30, 2002 and for the three- and nine-month periods then ended are unaudited and reflect all adjustments (consisting only of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management's discussion and analysis of financial condition and results of operations, contained in our Annual Report on Form 10-K for the year ended December 31, 2001. The results of operations for the three- and nine-month periods ended September 30, 2002 are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

Note 2 - Earnings Per Share

Basic net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the period. Diluted net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the period plus the weighted-average number of dilutive stock options granted to outside directors and employees. There were approximately 148,000 dilutive shares for the third quarter of 2002 and 180,000 dilutive shares for the first nine months of 2002.

Options considered antidilutive because the exercise price of the option exceeded the average price of our common stock for the applicable period totaled approximately 1,321,000 shares in the third quarter of 2002 and 1,072,000 shares in the first nine months of 2002.

In periods of net losses, basic and dilutive net loss per share of common stock are calculated by dividing net loss applicable to common stock by the weighted-average number of common shares outstanding during the period. In addition, the weighted-average number of options granted to outside directors and employees that are traditionally considered dilutive are added to anti-dilutive shares for those periods. Since we reported net losses for the three- and nine-month periods ended September 30, 2001, there were no dilutive shares for those periods and antidilutive shares totaled approximately 1,053,000 and 962,000 shares, respectively.

Note 3 - Ceiling Test Write-Down

The Securities and Exchange Commission requires full-cost companies to calculate a comparison of net capitalized costs of proved oil and gas properties to the discounted present value of future cash flows from the related reserves. The calculation is made using commodity prices at the end of the period held flat for the life of the reserves. If capitalized costs exceed discounted future cash flows, the assets are required to be written down to the value of the discounted cash flows. On September 30, 2001, natural gas prices closed at $1.83 per MMBtu. As a result of the low natural gas price on September 30, 2001, we recorded a $237.7 million non-cash write-down of our oil and gas properties during the third quarter of 2001. The write-down of oil and gas properties did not result in the loss of any proved reserve volumes.

Note 4 - Hedging Activities

We adopted Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective January 1, 2001. Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative's fair value are recognized in equity through other comprehensive income, to the extent the hedge is considered effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings.

We enter into hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. The primary objective of these activities is to reduce our exposure to the possibility of declining oil and natural gas prices during the term of the hedge. We do not enter into hedging transactions for trading purposes. We utilize two forms of hedging contracts: a fixed price swap and puts.

Under SFAS No. 133, our oil and natural gas put contracts are considered effective cash flow hedges and, therefore, changes in fair value of the puts are reflected in other comprehensive income. Put contracts are not costless; they are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contracts represents our maximum cash exposure. We are not obligated to make any further payments under the put contracts regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above that floor price. Oil contracts typically settle using the average daily closing prices for a calendar month. Natural gas contracts typically settle using the average closing prices of near month NYMEX futures contracts for the three days prior to the settlement date. Since over 90% of our production has historically been derived from the Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely match changes in market prices we receive for our production.

In addition to put contracts, we have utilized a fixed price swap to hedge a portion of our future natural gas production. A fixed price swap provides for monthly payments by us or to us based on the difference between the strike price and the agreed-upon average of NYMEX prices. Our natural gas swap contract was with a subsidiary of Enron Corp. Due to Enron's financial difficulties, there was no assurance that we would receive full or partial payment of any amounts that may have become due to us under the contract. Accordingly, this swap no longer qualifies as an effective hedge under SFAS No. 133. As a result, the change in fair value each period is recorded through earnings and amounts previously recorded in other comprehensive income are amortized through earnings over the remaining life of the swap.

At September 30, 2002, other comprehensive income included $2.9 million related to the ineffective natural gas swap that remains to be amortized over the original term of the swap contract, which extends through December 2003. In October 2002, we reached an agreement with Enron North America Corp. to purchase the portion of our fixed price natural gas swap contract settling subsequent to October 2002 for $5.9 million.

During the third quarter of 2002, we recognized non-cash expenses of $3.3 million related to commodity derivatives, $3.9 million of which represents amortized cost associated with put contracts that settled during the respective periods, partially offset by a $1.3 million credit related to the change in fair value of the swap contract. Also included in non-cash derivative expense for the three months ended September 30, 2002 is a $0.7 million charge from amortization of other comprehensive income related to the natural gas swap. At September 30, 2002, the unsettled put contracts were recorded as assets totaling $2.9 million and the unsettled natural gas swap was recorded as a liability totaling $6.6 million.

Our hedge positions for the period November 1, 2002 through December 31, 2003 are summarized as follows. Currently, we have no open hedge positions subsequent to December 31, 2003.

	Puts
	Gas			Oil
	Volume (BBtus)	Floor	Cost (millions)	Volume (MBbls)	Average Floor	Cost (millions)
2002	3,660	$3.50	$0.9	946	$24.77	$1.7
2003	27,375	3.00	4.6	-	-	-

During the third quarters of 2002 and 2001, we realized net increases in oil and gas revenues related to hedging transactions of $0.3 million and $2.6 million, respectively. For the first nine months of 2002 and 2001, oil and gas revenues included net increases (decreases) of $6.4 million and ($10.5) million, respectively, related to hedging transactions.

Note 5 - Long-Term Debt

Long-term debt consisted of the following:

	September 30, 2002	December 31, 2001
	(Unaudited)
	(In millions)

8¼% Senior Subordinated Notes Due 2011	$200	$200
8¾% Senior Subordinated Notes Due 2007	100	100
Bank debt	136	126

Total long-term debt	$436	$426

On December 5, 2001, we issued $200.0 million principal amount of 8 1/4% Senior Subordinated Notes due 2011. The Notes were sold at par value and we received net proceeds of $195.5 million. At September 30, 2002, $4.8 million and $0.4 million had been accrued in connection with the interest payments on the 8 1/4% Senior Subordinated Notes and the 8 3/4% Senior Subordinated Notes, respectively.

Borrowings outstanding at September 30, 2002 under our bank credit facility totaled $136.0 million, and letters of credit totaling $7.3 million have been issued under the facility. The borrowing base under the credit facility was increased to $300.0 million during June 2002. At September 30, 2002, we had $156.7 million of borrowings available under the credit facility and the weighted average interest rate under the credit facility was approximately 3.2%. The credit facility matures on December 20, 2004. The borrowing base limitation is re-determined periodically and is based on a borrowing amount established by the bank group resulting from an evaluation of the value of our proved oil and gas reserves.

Note 6 - Comprehensive Income

Comprehensive income (loss) consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001
	(In thousands) (Unaudited)
Net income (loss)	$13,693		($145,068	)	$35,933		($76,741	)
Other comprehensive income (loss), net of tax effect:
Cumulative effect of accounting change for derivatives	-		-		-		(26,114	)
Net change in fair value of derivatives	(2,682	)	12,913		(15,223	)	37,290
Amortization of other comprehensive income from the swap	435		-		1,191		-

Total other comprehensive income (loss)	(2,247	)	12,913		(14,032	)	11,176

Comprehensive income (loss)	$11,446		($132,155	)	$21,901		($65,565	)

Note 7 - Commitments and Contingencies

On July 29, 2002, we entered into a $28.0 million work commitment for at least five wells over a two-year period on the Pinedale Anticline in the Green River Basin in Wyoming. After the initial $28.0 million investment and the drilling of five wells, we will have earned a 50% working interest in the project area. We spudded the first commitment well during the third quarter of 2002 and expect the remaining wells to be drilled within the terms of the agreement. The Pinedale Anticline is a developing gas field in the Green River Basin in Wyoming.

Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Company-Lafitte, L.L.C. filed civil action number 2000-06437, in Harris County, Texas, against Stone Energy Corporation, seeking seismic data at Lafitte Field and unspecified damages. Subsequently, the same third party that had granted a data use license to Stone granted a similar license to plaintiffs at no cost and provided plaintiffs with the seismic data. We do not expect this matter to have a material adverse effect on our financial condition.

Note 8 - New Accounting Standards

In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations," effective for fiscal years beginning after June 15, 2002. This statement will require us to record the fair value of liabilities, before consideration of salvage, related to future asset retirement obligations in the period the obligation is incurred. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption, we will be required to recognize cumulative transition amounts for existing asset retirement obligation liabilities, asset retirement costs and accumulated amortization. An assessment of the impact of SFAS No. 143 on our financial condition and results of operations has yet to be completed. We expect that the adoption of SFAS No. 143 will result in increases in the capitalized costs of our oil and gas properties and the recognition of additional liabilities related to asset retirement obligations.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:

We have reviewed the accompanying condensed consolidated balance sheet of Stone Energy Corporation (a Delaware corporation) and subsidiary as of September 30, 2002, the related condensed consolidated statement of operations for the three-month and nine-month periods ended September 30, 2002, and the related condensed consolidated statement of cash flows for the nine-month period ended September 30, 2002. These financial statements are the responsibility of the Company's management. The condensed consolidated statement of operations for the three-month and nine-month periods ended September 30, 2001, and the related condensed consolidated statement of cash flows for the nine-month period ended September 30, 2001 of Stone Energy Corporation were reviewed by other accountants, who have ceased operations, whose report (dated October 30, 2001) stated that they were not aware of any material modifications that should be made to those statements for them to be in conformity with accounting principles generally accepted in the United States.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, which will be performed for the full year with the objective of expressing an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying financial statements at September 30, 2002, and for the three-month and nine-month periods then ended, for them to be in conformity with accounting principles generally accepted in the United States.

/s/ Ernst & Young LLP

New Orleans, Louisiana
November 1, 2002

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

This Form 10-Q and the information referenced herein contain statements that constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words "plan," "expect," "project," "estimate," "assume," "believe," "anticipate," "intend," "budget," "forecast," "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors.

When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in our Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Stone Energy Corporation are expressly qualified in their entirety by this cautionary statement.

Overview

Stone Energy Corporation is an independent oil and gas company focused primarily in the Gulf Coast Basin and is engaged in the acquisition and subsequent exploration, development, production and operation of oil and gas properties.

Our business strategy, which has remained consistent since 1990, is to increase production, cash flow and reserves through the acquisition, exploitation and development principally of mature oil and gas properties. Currently, our property base consists of 91 active properties, 56 in the Gulf Coast Basin and 35 in the Rocky Mountains, and 33 primary term leases in the Gulf of Mexico. We serve as operator on 55 of our active properties, which enables us to better control the timing and cost of rejuvenation activities. We believe that there will continue to be opportunities to acquire properties in the Gulf Coast Basin due to the increased focus by major and large independent companies on projects away from the onshore and shallow water shelf regions of the Gulf of Mexico.

Critical Accounting Policies

Our 2001 Annual Report on Form 10-K describes the accounting policies that we believe are critical to the reporting of our financial position and operating results and that require management's most difficult, subjective or complex judgments. Our most significant estimates are:

remaining proved oil and gas reserves;
timing of our future drilling activities;
future costs to develop and abandon our oil and gas properties;
the fair value of derivative positions; and
classification of unevaluated property costs.

This quarterly report on Form 10-Q should be read together with the discussion contained in our 2001 Annual Report on Form 10-K regarding these critical accounting policies.

Other Factors Affecting Our Business and Financial Results

In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This report on Form 10-Q should be read in conjunction with the discussion in our 2001 Annual Report on Form 10-K regarding these other risk factors.

Results of Operations

The following table sets forth certain operating information with respect to our oil and gas operations.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2002	2001	2002	2001
Production:
Oil (MBbls)	1,564	1,027	4,799	3,075
Gas (MMcf)	16,696	17,738	51,520	52,718
Oil and gas (MMcfe)	26,080	23,900	80,314	71,168
Sales data (in thousands) (a):
Oil	$42,413	$27,108	$116,952	$84,282
Gas	52,110	55,258	158,539	247,089
Total oil and gas sales	$94,523	$82,366	$275,491	$331,371
Average sales prices (a):
Oil (per Bbl)	$27.12	$26.40	$24.37	$27.41
Gas (per Mcf)	3.12	3.12	3.08	4.69
Oil and gas (per Mcfe)	3.62	3.45	3.43	4.66
Expenses (per Mcfe):
Normal lease operating expenses (b)	$0.60	$0.52	$0.57	$0.50
Salaries, general and administrative expenses	0.11	0.13	0.12	0.13
DD&A on oil and gas properties	1.50	1.97	1.50	1.75
(a) Includes the cash effects of hedging. (b) Excludes major maintenance expenses.

Net Income. For the third quarter of 2002, we reported net income totaling $13.7 million, or $0.52 per share, compared to a net loss reported for the third quarter of 2001 of ($145.1) million, or ($5.54) per share. Net income for the first nine months of 2002 totaled $35.9 million, or $1.36 per share, compared to a net loss of ($76.7) million, or ($2.94) per share, in the comparable 2001 period. All per share amounts are on a diluted basis.

The Securities and Exchange Commission requires full-cost companies to calculate a comparison of net capitalized costs of proved oil and gas properties to the discounted present value of future cash flows from the related reserves. The calculation is made using commodity prices at the end of the period held flat for the life of the reserves. If capitalized costs exceed discounted cash flows, the assets are required to be written down to the value of the discounted cash flows. On September 30, 2001, natural gas prices closed at $1.83 per MMBtu. As a result of the low natural gas price, we recorded a $237.7 million non-cash write-down of our oil and gas properties during the third quarter of 2001. The write-down of oil and gas properties did not result in the loss of any proved reserve volumes.

Oil and Gas Revenues. During the third quarter of 2002, oil and gas revenues totaled $94.5 million, compared to $82.4 million for the third quarter of 2001. Year-to-date 2002 oil and gas revenues totaled $275.5 million compared to $331.4 million during the comparable 2001 period. The decline in year-to-date 2002 revenues was primarily due to 26% lower average prices on a gas equivalent basis, offset in part by a 56% increase in oil production volumes.

Prices. Prices realized during the third quarter of 2002 averaged $27.12 per Bbl of oil and $3.12 per Mcf of natural gas. This represents a 5% increase, on an Mcfe basis, over third quarter 2001 average realized prices of $26.40 per Bbl of oil and $3.12 per Mcf of natural gas. Average realized prices during the first nine months of 2002 were $24.37 per Bbl of oil and $3.08 per Mcf of natural gas compared to $27.41 per Bbl of oil and $4.69 per Mcf of natural gas realized during the first nine months of 2001. All unit pricing amounts include the cash effects of hedging.

During the third quarter of 2002, hedging transactions increased the average price we received for natural gas by $0.02 per Mcf compared to a net increase of $0.15 per Mcf for the third quarter of 2001. Hedging transactions for natural gas during the first nine months of 2002 increased the average price we received for gas by $0.11 per Mcf compared to a net decrease of $0.21 per Mcf for the comparable 2001 period. Hedging transactions during the first nine months of 2002 increased the average price realized for oil by $0.16 per Bbl.

Production. Oil production during the third quarter of 2002 increased 52% to approximately 1.6 million barrels compared to approximately 1.0 million barrels produced during the third quarter of 2001. Natural gas production during the third quarter of 2002 decreased 6% to approximately 16.7 Bcf from third quarter of 2001 natural gas production of approximately 17.7 Bcf. On a gas equivalent basis, production volumes for the third quarter of 2002, after deferral of approximately 1 Bcfe of net production due to shut-ins for tropical storm Isidore, increased 9% to 26.1 Bcfe compared to third quarter 2001 production of 23.9 Bcfe. Year-to-date 2002 production totaled 4.8 million barrels of oil and 51.5 Bcf of gas while production for the first nine months of 2001 totaled 3.1 million barrels of oil and 52.7 Bcf of gas. The increase in 2002 oil production is primarily due to our acquisition of eight producing properties in December 2001.

During the fourth quarter of 2002, we experienced a Gulf Coast production shut-in related to hurricane Lili, which we estimate will ultimately result in the deferral of approximately 3 Bcfe of fourth quarter production. As a result, we expect net daily production to average 260-270 MMcfe for the fourth quarter of 2002.

Expenses. Normal lease operating expenses during the third quarter of 2002 totaled $15.6 million, or $0.60 per Mcfe, compared to $12.5 million, or $0.52 per Mcfe, for the comparable quarter in 2001. For the first nine months of 2002, normal lease operating expenses totaled $45.9 million, or $0.57 per Mcfe, compared to $35.5 million, or $0.50 per Mcfe, during the comparable period of 2001. Our December 2001 acquisition of eight producing properties increased the number of producing wells and the volume of oil production from 2001 levels. The combination of these factors, coupled with added costs associated with tropical storm Isidore, contributed to the increase in normal lease operating expenses during 2002.

Major maintenance expenses, which represent major repair and workover operations, totaled $5.1 million during the third quarter of 2002 compared to $1.8 million in the third quarter of 2001. Third quarter 2002 major maintenance expenses included workover operations on wells in the South Marsh Island Block 288 and Eugene Island Block 243 fields and platform painting at the East Cameron Block 64 field. We expect to incur major maintenance expenses during the fourth quarter of 2002 due to hurricane Lili; however, Stone believes that most of the costs will be covered by our insurance, which carries a $0.5 million deductible.

Depreciation, depletion and amortization (DD&A) expense on oil and gas properties for the third quarter of 2002 totaled $39.0 million, or $1.50 per Mcfe, compared to $47.1 million, or $1.97 per Mcfe, for the third quarter of 2001. Year-to-date 2002 DD&A expense on oil and gas properties totaled $120.7 million, or $1.50 per Mcfe, compared to $124.8 million, or $1.75 per Mcfe, for the first nine months of 2001. DD&A expense for the third quarter and first nine months of 2002 was positively impacted by higher period-end prices during 2002. For the nine months ended September 30, 2002, Stone estimates that proved reserve additions were less than volumes produced.

We financed fourth quarter 2001 acquisitions with $200.0 million principal amount of 8 1/4% Senior Subordinated Notes due 2011 and borrowings under our bank credit facility. As a result, interest expense, net of amounts capitalized ($2.2 million), for the third quarter of 2002 was $5.9 million, compared to $0.8 million during the third quarter of 2001. For the nine months ended September 30, 2002, interest expense, net of amounts capitalized ($6.4 million), totaled $17.4 million compared to $2.6 million during the comparable period in 2001.

In connection with our merger with Basin Exploration in 2001, we incurred related expenses totaling $0.1 million and $25.7 million during the three- and nine-month periods ended September 30, 2001, respectively.

New Accounting Standards

Hedging Activities

We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective January 1, 2001. Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative's fair value are recognized in equity through other comprehensive income, to the extent the hedge is considered effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings.

In October 2002, we reached an agreement with Enron North America Corp. to purchase the portion of our fixed price natural gas swap contract settling subsequent to October 2002 for $5.9 million. Other comprehensive income on October 1, 2002 included $2.9 million related to the swap contract that remains to be amortized over the original term of the swap contract, which extends through December 2003.

The following is a breakdown of non-cash derivative expenses for the respective periods:

	Three Months Ended September 30,			Nine Months Ended September 30,
	2002		2001	2002	2001
	(In thousands)
Amortization of costs of put contracts	$3,916		$889	$9,259	$2,223
Change in fair market value of swap	(1,249	)	-	753	-
Amortization of other comprehensive income from swap	670		-	1,832	-

Total non–cash derivative expenses	$3,337		$889	$11,844	$2,223

At September 30, 2002, the unsettled put contracts were recorded as assets totaling $2.9 million and the unsettled natural gas swap was recorded as a liability totaling $6.6 million. The fair value of the put contracts is determined by the counter-party based upon NYMEX prices.

In August 2002, we entered into gas put contracts with three separate counter-parties for a total of 75,000 MMBtu per day with a floor price of $3.00 per MMBtu. The contracts begin on January 1, 2003 and extend through December 31, 2003. The cost of these contracts totaling approximately $4.6 million will be amortized evenly through earnings over the life of the contracts. These contracts qualify as effective hedges under SFAS No. 133.

Liquidity and Capital Resources

Cash Flow. Net cash flow provided by operating activities for the first nine months of 2002 was $170.0 million compared to $270.8 million reported for the respective period in 2001. The decrease in net cash flow provided by operating activities is primarily attributable to lower oil and gas revenues caused by 26% lower average realized prices on a gas equivalent basis during the first nine months of 2002, offset in part by an increase in oil production volumes for the corresponding period. Net cash flow used in investing activities totaled $172.9 million and $285.9 million during the first nine months of 2002 and 2001, respectively, which primarily represents our investment in oil and gas properties. Net cash flow provided by (used in) financing activities totaled $13.1 million and ($43.4) million for the nine months ended September 30, 2002 and 2001, respectively. The use of financing cash flow during the 2001 period was the result of the $53.0 million repayment of debt made in connection with the termination of Basin Exploration's bank credit facility concurrent with the closing of the merger on February 1, 2001. As a result of these activities, cash and cash equivalents increased from $13.2 million as of December 31, 2001 to $23.3 million as of September 30, 2002.

Capital Expenditures. Capital expenditures during the third quarter of 2002 totaled $48.7 million and included $2.6 million of capitalized salaries, general and administrative expenses and incentive compensation expenses and $2.2 million of capitalized interest. Capital expenditures for the first nine months of 2002 totaled $155.5 million including $7.7 million of capitalized salaries, general and administrative expenses and incentive compensation expenses and $6.4 million of capitalized interest. These investments were financed by cash flow from operations, working capital and borrowings under our bank credit facility.

Budgeted Capital Expenditures. Our current estimated 2002 capital expenditures budget of approximately $210.0 million is allocated 90% to Gulf Coast Basin operations and 10% to Rocky Mountain activities. On July 29, 2002, we entered into a $28.0 million work commitment for at least five wells over a two-year period on the Pinedale Anticline in Wyoming. After the initial $28.0 million investment and the drilling of five wells, we will have earned a 50% working interest in the project area. We spudded the first commitment well during the third quarter of 2002 and expect the remaining wells to be drilled within the terms of the agreement. The Pinedale Anticline is a developing gas field in the Green River Basin in Wyoming.

Based upon our outlook on oil and gas prices and production rates, we expect cash flow from operations to be sufficient to fund the remaining 2002 capital expenditures budget. If oil and gas prices or production rates fall below our current expectations, we believe that the available borrowings under our bank credit facility will be sufficient to fund the capital expenditures in excess of operating cash flow.

Bank Credit Facility. As of November 8, 2002, we had a borrowing base under our credit facility of $300.0 million with availability of $156.7 million in borrowings. The credit facility matures on December 20, 2004. The borrowing base under the credit facility, which is re-determined periodically, is based on an amount established by the bank group resulting from an evaluation of the value of our proved oil and gas reserves.

Production Marketing Risk. The publicly disclosed deteriorating financial conditions and recently reduced credit ratings of certain purchasers of production increase the possibility that we may not receive payment for a portion of our future production. We have attempted to diversify our sales and obtain credit protections such as letters of credit, guarantees and prepayments from certain of our purchasers. We are unable to predict, however, what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

Reserve Replacement Risk. In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rate depends on reservoir characteristics. Gulf of Mexico reservoirs tend to experience steep declines, while declines in other regions after initial flush production tend to be relatively low. Our proved reserves are primarily derived from Gulf of Mexico reservoirs. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production, and corresponding revenues and cash flows, are highly dependent upon our level of success in finding or acquiring additional reserves. While our 2002 drilling program has generated a high drilling success rate, Stone estimates that proved reserve additions were less than volumes produced for the nine months ended September 30, 2002.

Environmental

Compliance with applicable federal, state and local environmental and safety regulations has not required any significant capital expenditures or materially affected our business or earnings. We believe we are in substantial compliance with environmental and safety regulations and foresee no material expenditures in the future; however, we are unable to predict the impact that compliance with future regulations may have on our capital expenditures, earnings, results of operations, financial condition or competitive position.

Defined Terms

Oil and condensate are stated in barrels ("Bbl") or thousand barrels ("MBbl"). Natural gas is stated herein in billion cubic feet ("Bcf"), million cubic feet ("MMcf") or thousand cubic feet ("Mcf"). Oil and condensate are converted to gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe, and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. BBtu represents one billion British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. In order to manage our exposure to oil and natural gas price declines we occasionally enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production. We do not enter into hedging transactions for trading purposes.

Our hedging policy provides that not more than one-half of our estimated production quantities can be hedged without the consent of the Board of Directors. In August 2002, we entered into additional gas put contracts, which were approved by our Board of Directors, to secure what we believe to be an attractive floor price for a portion of our 2003 gas production. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Hedging Activities for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Interest Rate Risk

At September 30, 2002, we had long-term debt outstanding of $436.0 million. Of this amount, $300.0 million, or 69%, bears interest at fixed rates averaging 8.4%. The remaining $136.0 million of debt outstanding at September 30, 2002 bears interest at a floating rate. At September 30, 2002, the weighted average interest rate under our floating-rate debt was 3.2%. Because the majority of our long-term debt at September 30, 2002 was at fixed rates, we consider our interest rate exposure at such date to be minimal. At September 30, 2002, we had no open interest rate hedge positions to reduce our exposure to changes in interest rates.

Since the filing of our Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to interest rates and commodity prices.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and our chief financial officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of the design and operation of Stone's disclosure controls and procedures as of a date within 90 days before the filing of this quarterly report on Form 10-Q. Based on this evaluation, our chief executive officer and chief financial officer believe:

Stone’s disclosure controls and procedures are designed to ensure that information required to be disclosed by Stone in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and
Stone’s disclosure controls and procedures were effective to ensure that material information was accumulated and communicated to Stone’s management, including Stone’s chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There were no significant changes in Stone's internal controls or, to their knowledge, in other factors that could significantly affect these controls subsequent to the date of their evaluation, nor were there any significant deficiencies or material weaknesses in Stone's internal controls. As a result, no corrective actions were required or undertaken.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits and Reports on Form 8-K

(a)		Exhibits
		*15.1 – Letter from Ernst & Young LLP dated November 11, 2002 regarding unaudited interim financial information.
*		Filed herewith
(b)		We filed the following reports on Form 8-K during the three months ended September 30, 2002:

Date of Event Reported
August 14, 2002

Item Reported
Item 9*

The information in the Form 8-K furnished pursuant to Item 9 is not considered to be “filed” for the purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	STONE ENERGY CORPORATION

Date: November 11, 2002	By: /s/ James H. Prince James H. Prince Senior Vice President, Chief Financial Officer and Treasurer (On behalf of Registrant and as Principal Financial Officer)

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

I, D. Peter Canty, President and Chief Executive Officer of Stone Energy Corporation, certify that:

I have reviewed this quarterly report on Form 10-Q of Stone Energy Corporation (the "Registrant");
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;

The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

a)	Designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b)	Evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90 days prior to the filing of this quarterly report (the "Evaluation Date"); and
c)	Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant's auditors and the audit committee of the Registrant's board of directors:

a)	All significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant's ability to record, process, summarize and report financial data and have identified for the Registrant's auditors any material weakness in internal controls; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal controls; and

The Registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

       /s/ D. Peter Canty
Name:  D. Peter Canty
Date:  November 11, 2002

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

I, James H. Prince, Senior Vice President, Chief Financial Officer and Treasurer of Stone Energy Corporation, certify that:

I have reviewed this quarterly report on Form 10-Q of Stone Energy Corporation (the "Registrant");
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;

a)	Designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b)	Evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90 days prior to the filing of this quarterly report (the "Evaluation Date"); and
c)	Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;